Jet and diesel selective hydrocracking

ABSTRACT

Systems and methods are provided for processing of challenged feedstocks to produce distillate fuel products, such as jet boiling range products and/or diesel boiling range products. The challenged feedstocks can have a high aromatics content, a low API gravity, and/or a low cetane index/cetane number. A feedstock can be processed to form distillate fuel products by processing the feedstock in reaction system including at least two stages. The first stage can perform an initial amount of hydrotreating and/or hydrocracking, while the second stage can include exposing a portion of the hydrotreated and/or hydrocracked effluent to a USY catalyst including a supported noble metal. The USY catalyst can have a desirable combination of catalyst properties. Processing a challenged feedstock in a second stage with the USY catalyst having a desirable combination of properties can allow for production of an increased yield of distillate fuel from the challenged feedstock.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 62/337,544, filed on May 17, 2016, the entire contents of which are incorporated herein by reference.

FIELD

Systems and methods are provided for production of distillate fuels.

BACKGROUND

Many refineries include thermal cracking processes as part of an overall process flow for handling challenged feeds. Thermal cracking processes have traditionally been effective for producing naphtha fractions suitable for use in motor gasoline products, but effective production of other high quality distillate fuel products has remained a challenge.

U.S. Patent Application Publication No. 2011/0315596 describes an integrated process for hydrocracking and dewaxing of hydrocarbons to form naphtha, diesel, and/or lubricant base stock boiling range products. The integrated process includes dewaxing and optionally hydrocracking under sour conditions, a separation to form a first diesel product and a bottoms product, and additional hydrocracking and dewaxing to form a second diesel product and optionally a lubricant base oil product. The hydrocracking and dewaxing catalysts can include base metals or can include Pd and/or Pt. An example of a hydrocracking catalyst is USY and an example of a dewaxing catalyst is ZSM-48.

U.S. Pat. No. 8,932,454 describes a method of making and using a Y zeolite hydrocracking catalyst. The Y zeolite catalyst has a small mesoporous peak in the pore size distribution of around 40 Å as measured by nitrogen desorption.

U.S. Pat. No. 8,778,171 describes a method of making and using a Y zeolite hydrocracking catalyst. The Y zeolite catalyst contains stabilized aggregates of Y zeolite primary crystallites having a size of 0.5 microns or less.

U.S. Patent Application Publication No. 2013/0341243 describes a hydrocracking process selective for improved distillate and improved lube yield and properties. A two-stage hydrocracking catalyst can be used for hydrocracking of a feed to form a converted portion suitable for diesel fuel production and an unconverted portion suitable for production of lubricant base stocks. The two-stage hydrocracking catalyst can correspond to a first stage catalyst including Pd and/or Pt supported on USY and a second stage catalyst including Pd and/or Pt supported on ZSM-48.

SUMMARY

In various aspects, methods are provided for producing a fuel product fraction from a challenged feed. The methods can include hydroprocessing a feedstock having a T95 boiling point of about 850° F. (−454° C.) or less under first hydroprocessing conditions to form a hydroprocessed effluent. The feedstock can have an aromatics content of at least about 40 wt % and/or a cetane index of about 35 or less. At least a portion of the hydroprocessed effluent can be fractionated to form at least a first fraction and a second fraction. In some aspects, the first fraction can include at least a portion of a distillate boiling range product while at least a portion of the second fraction can be hydrocracked in the presence of hydrocracking catalyst under second hydrocracking conditions to form a hydrocracked effluent. In other aspects, the first fraction can be a lower boiling fraction, such as a naphtha fraction, while the second fraction contains at least a portion of a distillate boiling range product. In such other aspects, a portion of the second fraction can be hydrocracked while another portion can be separated to recover the distillate boiling range product. The hydrocracking catalyst can comprise USY zeolite having a unit cell size of about 24.30 Å or less and/or a silica to alumina ratio of at least about 50 and/or an Alpha value of about 20 or less. The hydrocracking catalyst can further include about 0.1 wt % to about 5.0 wt % of a Group 8-10 noble metal supported on the hydrocracking catalyst. At least a portion of the hydrocracked effluent can be fractionated to form at least a third distillate boiling range fraction and optionally a fourth fraction. Depending on the aspect, the first fraction, the third fraction, or a combination thereof, or the second fraction the fourth fraction, or a combination thereof, can comprise the distillate boiling range product. The distillate boiling range product can have an aromatics content of about 20 wt % or less and/or a cetane index of at least about 50. Optionally, the distillate boiling range product can have a naphthene content of at least about 50 wt %.

In some aspects, the fractionation of the at least a portion of the hydroprocessed effluent and the fractionation of the at least a portion of the hydrocracked effluent can be performed in a divided wall column fractionator. In such aspects, the second fraction can be different from the fourth fraction. In other aspects, the fractionation of the at least a portion of the hydroprocessed effluent and the fractionation of the at least a portion of the hydrocracked effluent can be performed in a common fractionator. In such aspects, the second fraction and the fourth fraction can be the same fraction.

In still another aspect, a distillate boiling range product is provided, the product having a cetane index of at least about 50, an aromatics content of about 10 wt % or less, a naphthene content of at least about 50 wt %, a sulfur content of about 10 wppm or less, and an API gravity of at least about 35.

In yet another aspect, a system for producing a fuel product fraction is provided. The system can include a hydrotreating reactor comprising a hydrotreating feed inlet, a hydrotreating effluent outlet, and at least one fixed catalyst bed of a hydrotreating catalyst. The hydrotreating effluent outlet can be in fluid communication with a separation stage via a first separation stage inlet. The separation stage can further include a plurality of separation stage liquid effluent outlets. One or more of the separation stage liquid effluent outlets corresponding to product outlets. The system can also include a hydrocracking reactor comprising a hydrocracking feed inlet, a hydrocracking effluent outlet, and at least one fixed catalyst bed of a hydrocracking catalyst. The hydrocracking feed inlet can be in fluid communication with at least one separation stage liquid effluent outlet. Optionally, the at least one separation stage liquid effluent outlet that is in fluid communication with the hydrocracking feed inlet can also correspond to one of the product outlets. The hydrocracking effluent outlet can be in fluid communication with a second separation stage inlet of the separation stage. The hydrocracking catalyst in the hydrocracking reactor can comprise USY zeolite having a unit cell size of about 24.30 Å or less, a silica to alumina ratio of at least about 50, and an Alpha value of about 20 or less. The hydrocracking catalyst can further include about 0.1 wt % to about 5.0 wt % of a Group 8-10 noble metal supported on the hydrocracking catalyst. Optionally, an additional hydrocracking reactor can be included after the hydrotreating reactor and prior to the separation stage, the additional hydrocracking reactor providing indirect fluid communication between the hydrotreating reactor and the separation stage.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 schematically shows an example of a configuration suitable for processing a feedstock to form a distillate fuel fraction.

FIG. 2 schematically shows another example of a configuration suitable for processing a feedstock to form a distillate fuel fraction.

FIG. 3 shows results from processing of various distillate boiling range fractions.

DETAILED DESCRIPTION Overview

In various aspects, systems and methods are provided for processing of challenged feedstocks to produce distillate fuel products, such as jet boiling range products and/or diesel boiling range products. The challenged feedstocks can include feedstocks having a high aromatics content, a low API gravity, a low cetane index and/or cetane number, or a combination thereof. A feedstock can be processed to form distillate fuel products by processing the feedstock in reaction system including at least two stages. The first stage can perform an initial amount of hydrotreating and/or hydrocracking, while the second stage can include exposing a portion of the hydrotreated and/or hydrocracked effluent to a USY catalyst including a supported noble metal, such as Pt and/or Pd. The USY catalyst can have a desirable combination of catalyst properties, such as a unit cell size of about 24.30 Å or less (or about 24.24 Å or less), a silica to alumina molar (Si/Al₂) ratio of at least about 50 (or at least about 80), and an alpha value of about 20 or less (or about 10 or less). Processing a challenged feedstock in a second stage with the USY catalyst having a desirable combination of properties can allow for production of an increased yield of distillate fuel from the challenged feedstock.

In various aspects, a feedstock can be initially hydrotreated and/or hydrocracked. The effluent from the initial hydrotreatment and/or hydrocracking can be separated to form distillate fuel boiling range products and higher boiling range products, typically resulting from an unconverted portion. The unconverted portion can then be hydrocracked, with optional recycle of any remaining unconverted portion for further hydrocracking. Optionally, a common fractionator or other separator can be used for separating distillate fuel boiling range products from unconverted portions of the feed that have a boiling range above the distillate fuel boiling range. Optionally, the hydrocracked products can be dewaxed to provide distillate fuel boiling range products having improved cold flow properties.

FIG. 1 shows an example of a general processing configuration suitable for processing a feedstock to produce distillate fuels. In FIG. 1, a feedstock 105 can be introduced into a first reactor 110. A reactor such as first reactor 110 can include a feed inlet and an effluent outlet. First reactor 110 can correspond to a hydrotreating reactor, a hydrocracking reactor, or a combination thereof. Optionally, a plurality of reactors can be used to allow for selection of different conditions. For example, if both a first reactor 110 and optional second reactor 120 are included in the reaction system, first reactor 110 can correspond to a hydrotreatment reactor while second reactor 120 can correspond to a hydrocracking reactor. Additionally or alternately, at least a portion of the catalyst in at least one reactor can correspond to dewaxing catalyst. For example, in a configuration where second reactor 120 includes hydrocracking catalyst, the reactor can also include a portion of dewaxing catalyst. Still another option could be to have a separate reactor (not shown) for the dewaxing catalyst, to allow for further flexibility in selecting reaction conditions for dewaxing. Yet other options for arranging reactor(s) and/or catalysts within the reactor(s) to perform initial hydrotreating and/or hydrocracking of a feedstock can also be used. Optionally, if a configuration includes multiple reactors in the initial stage, a gas-liquid separation can be performed between reactors to allow for removal of light ends and contaminant gases. In aspects where the initial stage includes a hydrocracking reactor, the hydrocracking reactor in the initial stage can be referred to as an additional hydrocracking reactor.

The hydroprocessed effluent 125 from the final reactor (such as reactor 120) of the initial stage can then be passed into a fractionator 130, or another type of separation stage. Optionally, fractionator 130 can correspond to a single fractionation tower, such as a divided wall column fractionator. Optionally, a separation stage can include a plurality of separators to facilitate separation of different boiling ranges of an effluent. Optionally, a fractionation tower can be used in conjunction with one or more other separators as part of a separation stage. Fractionator 130 (or other separation stage) can separate the hydroprocessed effluent to form at least a distillate fuel boiling range fraction 137 and a bottoms fraction 135. The distillate fuel fraction 137 can be suitable for incorporation into a distillate fuel pool. The bottoms fraction 135 can undergo further hydrocracking in the presence of a USY zeolite in second stage reactor 140. In the configuration shown in FIG. 1, the effluent 145 from second stage reactor 140 can be returned to fractionator 130 for separation. Alternatively, a separate fractionator can be used for processing the effluent 145 from second stage reactor 140, with a recycle loop set up to allow for extinction recycle of fractionator bottoms to generate additional distillate fuel.

It is noted that in a configuration similar to the configuration in FIG. 1, the only portion of the hydroprocessed effluent that is exposed to the second stage USY catalyst is the portion of the effluent that boils above the distillate fuel boiling range. As a result, in some aspects the goal of the initial hydroprocessing stage (hydrotreating and/or hydrocracking and/or optional dewaxing) can be to hydroprocess the feedstock sufficiently to produce a “sweet” effluent with a sulfur/nitrogen content that is suitable for exposure to a noble metal USY hydrocracking catalyst. This can correspond to performing a reduced or minimized amount of conversion of the portion of the feed that boils above about 700° F. (−371° C.).

In the configuration shown in FIG. 1, the final reactor (such as reactor 120) in the initial stage can be referred to as being in direct fluid communication with an inlet to the fractionator 130 (or an inlet to another type of separation stage). The other reactors in the initial stage can be referred to as being in indirect fluid communication with the inlet to the separation stage, based on the indirect fluid communication provided by the final reactor in the initial stage. The reactors in the initial stage can generally be referred to as being in fluid communication with the separation stage, based on either direct fluid communication or indirect fluid communication

FIG. 2 shows an alternative configuration for processing a feedstock to produce distillate fuels. In the alternative configuration in FIG. 2, similar types of reactors and separators can be used, but with different fractionation points. For example, in the configuration in FIG. 2, fractionator 130 can separate the hydroprocessed effluent to form at least a naphtha fuel boiling range fraction 237 and a bottoms fraction 235. The naphtha fuel fraction 237 can be suitable for incorporation into a gasoline fuel pool. In this alternative configuration, the bottoms fraction 235 can correspond to a distillate fuel fraction. In this type of alternative configuration, a distillate fuel product 242 (or optionally one or more distillate fuel products 242) generated by the configuration can be separated from bottoms fraction 235 prior to passing bottoms fraction 235 into second stage reactor 140 to undergo further hydrocracking in the presence of a USY zeolite. Effluent 245 from second stage reactor 140 can then be returned to fractionator 130 for separation.

In this discussion, the naphtha boiling range is defined as about 50° F. (˜10° C.), roughly corresponding to the lowest boiling point of a pentane isomer) to about 315° F. (˜157° C.). The jet boiling range is defined as about 315° F. (˜157° C.) to about 460° F. (˜238° C.). The diesel boiling range is defined as about 460° F. (˜238° C.) to about 800° F. (˜427° C.). The distillate fuel boiling range (jet plus diesel), is defined as about 315° F. (˜157° C.) to about 800° F. (˜427° C.). Compounds (C₄₋) with a boiling point below the naphtha boiling range can be referred to as light ends. It is noted that due to practical consideration during fractionation (or other boiling point based separation) of hydrocarbon-like fractions, a fuel fraction formed according to the methods described herein may have a T5 or a T95 distillation point corresponding to the above values, as opposed to having initial/final boiling points corresponding to the above values.

In this discussion, unless otherwise specified, references to a liquid effluent or a liquid product are references to an effluent or product that is a liquid at about 25° C. and about 100 kPa (˜1 atm).

In this discussion, conditions may be provided for various types of hydroprocessing of feeds or effluents. Examples of hydroprocessing can include, but are not limited to, one or more of hydrotreating, hydrocracking, catalytic dewaxing, and hydrofinishing/aromatic saturation. Such hydroprocessing conditions can be controlled to have desired values for the conditions (e.g., temperature, pressure, LHSV, treat gas rate) by using at least one controller, such as a plurality of controllers, to control one or more of the hydroprocessing conditions. In some aspects, for a given type of hydroprocessing, at least one controller can be associated with each type of hydroprocessing condition. In other aspects, one or more of the hydroprocessing conditions can be controlled by an associated controller. Examples of structures that can be controlled by a controller can include, but are not limited to, valves that control a flow rate, a pressure, or a combination thereof; heat exchangers and/or heaters that control a temperature; and one or more flow meters and one or more associated valves that control relative flow rates of at least two flows. Such controllers can optionally include a controller feedback loop including at least a processor, a detector for detecting a value of a control variable (e.g., temperature, pressure, flow rate), and a processor output for controlling the value of a manipulated variable (e.g., changing the position of a valve, increasing or decreasing the duty cycle and/or temperature for a heater). Optionally, at least one hydroprocessing condition for a given type of hydroprocessing may not have an associated controller.

Feedstocks

A wide range of petroleum and chemical feedstocks can be hydroprocessed in accordance with the invention. Suitable feedstocks include whole and reduced petroleum crudes, atmospheric, cycle oils, gas oils, including vacuum gas oils and coker gas oils, light to heavy distillates including raw virgin distillates, hydrocrackates, hydrotreated oils, slack waxes, Fischer-Tropsch waxes, raffinates, and mixtures of these materials. Examples of suitable types of feedstock can include, but are not limited to, FCC cycle oils, light coker gas oils, and virgin atmospheric gas oils with elevated aromatics content.

One way of defining a feedstock is based on the boiling range of the feed. One option for defining a boiling range is to use an initial boiling point for a feed and/or a final boiling point for a feed. Another option is to characterize a feed based on the amount of the feed that boils at one or more temperatures. For example, a “T5” boiling point for a feed is defined as the temperature at which 5 wt % of the feed will boil off. Similarly, a “T95” boiling point is a temperature at 95 wt % of the feed will boil. Boiling points, including fractional weight boiling points, can be determined using a suitable ASTM method, such as ASTM D2887.

Typical feeds include, for example, feeds with an initial boiling point and/or a T5 boiling point of at least about 400° F. (˜204° C.), e.g., at least about 450° F. (˜232° C.). Additionally or alternatively, the final boiling point, T95 boiling point and/or T90 boiling point of the feed can be about 850° F. (˜454° C.) or less, e.g., about 800° F. (˜427° C.) or less or about 750° F. (˜399° C.) or less. It is noted that feeds with lower T5 boiling points may also be suitable. However, the resulting yields of such lower boiling feeds can be characterized relative to the ˜400° F.+(˜204° C.+) portion of the feed.

In some aspects, a feedstock for a process as described herein can have an aromatics content of at least about 45 wt %, such as up to about 90 wt % or more. An example of a suitable test for determining aromatics content can be ASTM D5186, which can determine aromatics based on supercritical fluid chromatography. For example, the feedstock can have an aromatics content of about 45 wt % to about 90 wt %, such as about 45 wt % to about 85 wt %, about 45 wt % to about 80 wt %, about 45 wt % to about 75 wt %, about 50 wt % to about 90 wt %, about 50 wt % to about 85 wt %, about 50 wt % to about 80 wt %, about 50 wt % to about 75 wt %, about 55 wt % to about 90 wt %, about 55 wt % to about 85 wt %, about 55 wt % to about 80 wt %, or about 55 wt % to about 75 wt %. This can be in contrast to a conventional feed for distillate fuel production, which can have an aromatics content of 35 wt % or less.

Another option for characterizing the aromatics in a feedstock can be to characterize the percentage of carbons in a feed that are part of an aromatic ring. This can be determined, for example, by ¹³C-NMR. The aromaticity can be defined as number of carbons in an aromatic ring expressed as a percentage relative to the total number of carbons in the feed. In various aspects, the aromaticity of a feed can be about 30% to about 70%, or about 40% to about 70%, or about 50% to about 70%, or about 30% to about 60%, or about 40% to about 60%, or about 30% to about 50%. Still another option can be to characterize the hydrogen content of a feed. In various aspects, the hydrogen content of a feed can be from 8.0 wt % to 10.0 wt %, or 8.5 wt % to 10.0 wt %.

Additionally or alternately, a feedstock for a process as described herein can have a cetane index (ASTM D4737) that is low relative to a desirable value for a distillate fuel product. In various aspects, the cetane index of a feed can be about 35 or less, or about 30 or less, or about 25 or less, such as down to about 10 or possibly lower.

Additionally or alternately, a feedstock for a process as described herein can have an API gravity that is low relative to a desirable value for a distillate fuel product. In various aspects, the API gravity of a feed can be about 20.0 or less, or about 18.0 or less, or about 16.5 or less, or about 15.0 or less, such as down to about 10.0 or possibly lower.

Additionally or alternately, the sulfur content of a feed can be at least about 5000 ppm by weight of sulfur, or at least about 10000 wppm, or at least about 20000 wppm, or at least about 30000 wppm, such as up to about 50000 wppm or more. Additionally or alternately, the nitrogen content of a feed can be about 100 wppm to about 4000 wppm, or about 100 wppm to about 2000 wppm, or about 100 wppm to about 1000 wppm, or about 200 wppm to about 4000 wppm, or about 200 wppm to about 2000 wppm, or about 200 wppm to about 1000 wppm.

In some embodiments, at least a portion of the feed can correspond to a feed derived from a biocomponent source. In this discussion, a biocomponent feedstock refers to a hydrocarbon feedstock derived from a biological raw material component, from biocomponent sources such as vegetable, animal, fish, and/or algae. Note that, for the purposes of this document, vegetable fats/oils refer generally to any plant based material, and can include fat/oils derived from a source such as plants of the genus Jatropha. Generally, the biocomponent sources can include vegetable fats/oils, animal fats/oils, fish oils, pyrolysis oils, and algae lipids/oils, as well as components of such materials, and in some embodiments can specifically include one or more type of lipid compounds. Lipid compounds are typically biological compounds that are insoluble in water, but soluble in nonpolar (or fat) solvents. Non-limiting examples of such solvents include alcohols, ethers, chloroform, alkyl acetates, benzene, and combinations thereof.

Second Stage Hydrocracking with USY Catalyst

In various aspects, the second stage for processing of a feedstock can correspond to exposing at least a portion of the feedstock to a USY catalyst with a desirable combination of properties. The properties can be measured prior to the addition of loaded metals on the catalyst. The USY catalyst can have a unit cell size of about 24.30 Å or less, or about 24.27 Å or less, or about 24.24 Å or less. Additionally or alternately, the USY catalyst can have a silica to alumina ratio of at least about 50, or at least about 70, or at least about 90, or at least about 100, or at least about 110, or at least about 120, or at least about 125, and optionally up to about 250 or more, or not more than 1000. This level of silica to alumina ratio can optionally correspond to a “dealuminated” version of the catalyst. Additionally or alternately, the USY catalyst can have an alpha value of about 20 or less, or about 10 or less. The alpha value test is a measure of the cracking activity of a catalyst and is described in U.S. Pat. No. 3,354,078 and in the Journal of Catalysis, Vol. 4, p. 527 (1965); Vol. 6, p. 278 (1966); and Vol. 61, p. 395 (1980), each incorporated herein by reference as to that description. The experimental conditions of the test used herein include a constant temperature of 538° C. and a variable flow rate as described in detail in the Journal of Catalysis, Vol. 61, p. 395.

In an aspect, the feed to the second stage can be exposed to the USY catalyst under hydrocracking conditions that include one or more of: a weight average bed temperature (WABT) from about 550° F. (about 288° C.) to about 800° F. (about 427° C.); a total pressure from about 300 psig (about 2.1 MPag) to about 3000 psig (about 20.7 MPag), for example from about 700 psig (about 4.8 MPag) to about 2000 psig (about 13.8 MPag); an LHSV from about 0.1 hr⁻¹ to about 20 hr⁻¹, for example from about 0.2 hr⁻¹ to about 10 hr⁻¹; and a hydrogen treat gas rate from about 500 scf/bbl (about 85 Nm³/m³) to about 10000 scf/bbl (about 1700 Nm³/m³), for example from about 750 scf/bbl (about 130 Nm³/m³) to about 7000 scf/bbl (about 1200 Nm³/m³) or from about 1000 scf/bbl (about 170 Nm³/m³) to about 5000 scf/bbl (about 850 Nm³/m³).

A USY hydrocracking catalyst can also include a binder material. Suitable binder materials include materials selected from metal oxides, zeolites, aluminum phosphates, polymers, carbons, and clays. Most preferable, the binder is comprised of at least one metal oxide, preferably selected from silica, alumina, silica-alumina, amorphous aluminosilicates, boron, titania, and zirconia. Preferably, the binder is selected from silica, alumina, and silica-alumina. In a preferred embodiment, the binder is comprised of pseudoboehmite alumina.

A catalyst can contain from 0 to 99 wt % binder materials, or about 25 to about 80 wt %, or about 35 to 75 wt %, or about 50 to about 65 wt % of the overall final hydrocracking catalyst. In other preferred embodiments, a hydrocracking catalyst can be less than 80 wt % binder materials, or less than 75 wt %, or less than 65 wt %, or less than 50 wt %.

A hydrocracking catalyst containing USY zeolite may also contain additional zeolites or molecular sieves. In some aspects, a hydrocracking catalyst can further comprise at least one of the following molecular sieves: beta, ZSM-5, ZSM-11, ZSM-57, MCM-22, MCM-49, MCM-56, ITQ-7, ITQ-27, ZSM-48, mordenite, zeolite L, ferrierite, ZSM-23 MCM-68, SSZ-26/-33, SAPO-37, ZSM-12, ZSM-18, and EMT faujasites. In such aspects, the hydrocracking catalyst can contain the EMY zeolite in an amount of at least 10 wt %, more preferably at least at least 25 wt %, and even more preferably at least 35 wt % or even at least 50 wt % based on the finished catalyst, particularly when a binder is utilized.

A USY hydrocracking catalyst can also include at least one hydrogenating metal component supported on the catalyst. Examples of such hydrogenating metal components can include one or more noble metals from Groups 8-10 of the IUPAC periodic table. Optionally but preferably, the hydrocracking catalyst can include at least one Group 8/9/10 metal selected from Pt, Pd, Rh and Ru (noble metals), or combinations thereof. In another aspect, the hydrocracking catalyst is comprised at least one Group 8/9/10 metal selected from Pt, Pd, or a combination thereof. In still another aspect, the hydrocracking catalyst is comprised of Pt. The at least one hydrogenating metal may be incorporated into the catalyst by any technique known in the art. A preferred technique for active metal incorporation into the catalyst herein is the incipient wetness technique.

The amount of active metal in the catalyst can be at least 0.1 wt % based on catalyst, or at least 0.15 wt %, or at least 0.2 wt %, or at least 0.25 wt %, or at least 0.3 wt %, or at least 0.5 wt % based on the catalyst. For embodiments where the Group 8/9/10 metal is Pt, Pd, Rh, Ru, or a combination thereof, the amount of active metal is preferably from 0.1 to 5 wt %, more preferably from 0.2 to 4 wt %, and even more preferably from 0.25 to 3.5 wt %.

Examples of suitable zeolite Y catalysts for the processes described herein can include catalysts based on aggregated Y zeolite (or Meso-Y) and Extra Mesoporous Y (“EMY”) zeolite. Additional description of aggregated Y zeolite (Meso-Y) can be found in U.S. Pat. No. 8,778,171, which is incorporated herein by reference with regard to description of aggregated Y zeolite and methods for making a catalyst containing aggregated Y zeolite. Additional description of Extra Mesoporous Y zeolite can be found in U.S. Pat. No. 8,932,454, which is incorporated herein by reference with regard to description of EMY zeolite and methods for making a catalyst containing EMY zeolite.

Briefly Meso-Y refers to a stabilized aggregated form of zeolite Y that comprises small primary crystallites and secondary particles of larger size. At least 80%, e.g., at least 90% or at least 95%, of the primary crystallites may be aggregated or clustered to form the secondary particles. The ratio of the average size (width/diameter) of the secondary particles to the average size (width/diameter) of the primary crystallites, when the outer (i.e., external) surfaces of the secondary particles are viewed, may be at least 3:1, for example at least 5:1 or at least 10:1. When the outer surfaces of the secondary particles are viewed, e.g., in an SEM image, the average size of the primary crystallites in a secondary particle may be about 0.5 μm or less, for example about 0.3 μm or less, about 0.2 μm or less, or about 0.1 μm or less, whereas the average size of the secondary particles may be about 0.8 μm or more, for example about 1.0 μm or more or about 2.0 μm or more. At least 80%, e.g., at least 90% or at least 95%, of the aggregated secondary particles may comprise at least 5, for example at least 10, primary crystallites. These primary crystallites and secondary particles as described herein may be observable, e.g., by an SEM under sufficient conditions including appropriate magnification and resolution.

The average sizes of the primary crystallites and secondary particles can be determined, for instance, by viewing one or more sufficient two-dimensional SEM images of the secondary particles and approximating the shape of the primary crystallites and secondary particles roughly as two-dimensional spherical projections (circles). When percentages (e.g., 80%, 90%, 95%, or the like) of primary crystallites and secondary particles are referred to herein, it should be understood that these percentages are based on numbers of these particles. Although SEM images referred to herein do not necessarily depict all of the particles in an entire batch of primary crystallites and secondary particles, it should also be understood that the SEM images referred to herein are viewed as representative of an entire batch of primary crystallites and secondary particles, including even those particles not specifically observed.

An advantage of the present invention over the prior art, is that in the prior art, the zeolite crystals typically require a significant amount of binder material in order to get obtain sufficient mesoporosity which is defined herein as pore diameters from 2 to 30 nm (20 to 300 angstroms, Å) for optimum hydrocracking of hydrocarbon feedstocks. In the present invention, the zeolite is aggregated into a structure containing a high relative mesoporosity and as such, the hydrocracking catalyst can made with very low concentration levels of binders and still maintain the necessary overall mesoporosity of the hydrocracking catalyst. While the catalysts of invention can contain from 0 to 99 wt % binder materials, due to the high mesoporosity of the aggregate Y zeolite, in preferred embodiments, the binders levels can be about 0 to about 80 wt %, more preferably, from about 5 to 50 wt %, or even from about 5 to about 25 wt % of the overall final hydrocracking catalyst. In other preferred embodiments, the hydrocracking catalyst can be less than 50 wt %, more preferably less than 25 wt %, and most preferably less than 10 wt % binder materials. As noted, in embodiments, the aggregated Y zeolites of the present invention may be used as the final catalyst without any binder materials.

The secondary particles may possess an external surface area of about 10 m.sup.2/g or more, for example, about 20 m²/g or more or about 40 m²/g or more, especially after undergoing calcination and/or steaming. Conventional forms of zeolite Y, such as those having non-aggregated primary crystallites with a size of 1 micron or more, tend to have an external surface area of less than 10 m²/g. The relatively high external surface area of the secondary particles can be an indication generally of porous gaps between individual primary crystallites, and specifically of mesopores in the internal regions of the secondary particles. A single crystal of comparable size in the form of a generally spherical shape (with angularity or edges developed) would be expected to have a smaller external surface area.

The aggregated form of zeolite Y may have a mesopore volume of at least 0.025 cm³/gram (abbreviated cc/g herein), particularly in the inter-crystalline regions of the aggregates. Non-aggregated forms of zeolite Y thus tend to lack mesopores (which are defined herein as pores having a diameter from about 20 to about 300 Angstroms).

Briefly, an EMY zeolite can be a Y structure zeolite with a suppressed “small mesopore peak” that is commonly found associated within the “small mesopores” (30 to 50 Å pore diameters) of commercial Y-type zeolites, while maintaining a substantial volume of pores in the “large mesopores” (greater than 50 to 500 Å pore diameters) of the zeolite. International Union of Pure and Applied Chemistry (“IUPAC”) standards defines “mesopores” as having pore diameters greater than 20 to less than 500 Angstroms (Å). However, the standard nitrogen desorption measurements as used herein do not provide pore volume data below about 22 Å. Additionally, since the “small mesopore peak” found in Y zeolites are substantially confined between the 30 and 50 Å ranges, it is sufficient to define the measurable mesoporous pore diameter range for the purposes of this invention as pore diameters from 30 to 500 Angstroms (Å).

As utilized herein, the terms “Small Mesopore(s)” or “Small Mesoporous” are defined as those pore structures in the zeolite crystal with a pore diameter of 30 to 50 Angstroms (Å). Similarly, the terms “Large Mesopore(s)” or “Large Mesoporous” as utilized herein are defined as those pore structures in the zeolite crystal with a pore diameter of greater than 50 to 500 Angstroms (Å). The terms “Mesopore(s)” or “Mesoporous” when utilized herein alone (i.e., not in conjunction with a “small” or “large” adjective) are defined herein as those pore structures in the zeolite crystal with a pore diameter of 30 to 500 Angstroms (Å). Unless otherwise noted, the unit of measurement used for mesoporous pore diameters herein is in Angstroms (Å).

The terms “Small Mesopore Volume”, “Small Mesoporous Volume”, “Large Mesopore Volume”, and “Large Mesoporous Volume” of a material as used herein are defined as the total pore volume of the pores per unit mass in the Small Mesopore/Large Mesopore range (respectively) as measured and calculated by ASTM Standard D 4222 “Determination of Nitrogen Adsorption and Desorption Isotherms of Catalysts and Catalyst Carriers by Static Volumetric Measurements”; ASTM Standard D 4641 “Calculation of Pore Size Distributions of Catalysts from Nitrogen Desorption Isotherms”; and “The Determination of Pore Volume and Area Distributions in Porous Substances, I. Computations from Nitrogen Isotherms”, by Barrett, E. P.; Joyner, L. S.; and Halenda, P. P.; Journal of American Chemical Society; vol. 73, pp. 373-380 (1951), all of which are incorporated herein by reference. Unless otherwise noted, the unit of measurement for mesopore volume is in cm³/g. The term “Large-to-Small Pore Volume Ratio” or “LSPVP,” of a material as used herein is defined as the ratio of the Large Mesopore Volume to the Small Mesopore Volume (dimensionless).

The term “BJH N₂ Desorption Plot” as used herein is defined as a plot of the change in unit volume of a mesoporous material as a function of the pore diameter of the mesoporous material. Herein, the “BJH N₂ Desorption Plot” is shown as the pore volume calculated as dV/d log D (in cm³/g) vs. the pore diameter (in nanometers) as determined by the ASTM Standard D 4222, ASTM Standard D 4641, and “The Determination of Pore Volume and Area Distributions in Porous Substances, I. Computations from Nitrogen Isotherms”, by Barrett, E. P.; Joyner, L. S.; and Halenda, P. P.; Journal of American Chemical Society; vol. 73, pp. 373-380 (1951), (i.e., the “BJH method” for calculating the pore distribution of a porous substance) as referenced in the definitions above. The BJH N₂ Desorption Plot should be generated from approximately 15 to 30 data points at approximately equidistant positions on a logarithmic x-axis of the pore diameter (nanometers) between the values of 3 to 50 nanometers (30 to 500 Å). The pore volume value on the y-axis of the plot is commonly calculated in industry equipment as an interpolated value of the incremental change in volume, dV (Where V is in cm³, and dV is in cm³) divided by the incremental change in the log of the pore diameter, d log D (where D is in nanometers, and d log D is unitless) and is adjusted to the unit weight of the sample in grams. Therefore, the “pore volume” (which is the common term utilized in the industry) as shown on the y-axis of the BJH N₂ Desorption Plot may be more appropriately described as an incremental pore volume per unit mass and is expressed herein in the units cm³/g. It should be noted that the “pore volume” value on the y-axis of the BJH N2 Desorption Plot is not synonymous with the “Small Mesopore Volume” and “Large Mesopore Volume” as described above which are calculated unit pore volumes over a range of pore diameters. However, these calculations and terms as used herein are familiar to those of skill in the art. All measurements and data plots as utilized herein were made with a Micromeritics® Tristar 3000® analyzer.

The term “Small Mesopore Peak” as used herein refers to the property of a zeolite and is defined as the maximum pore volume value calculated as dV/d log D (y-axis) on a BJH N₂ Desorption Plot as described above (pore volume vs. pore diameter) between the 30 Å and 50 Å pore diameter range (x-axis). Unless otherwise noted, the unit of measurement for the small mesopore peak is in cm³/g.

The term “Large Mesopore Peak” used herein refers to the property of a zeolite and is defined as the maximum pore volume value calculated as dV/d log D (y-axis) on a BJH N₂ Desorption Plot as described above (pore volume vs. pore diameter) between the 50 Å and 500 Å pore diameter range (x-axis). Unless otherwise noted, the unit of measurement for the large mesopore peak is in cm³/g.

The term “BET Surface Area” for a material as used herein is defined as the surface area as determined by ASTM Specification D 3663. Unless otherwise noted, the unit of measurement for surface area is in m²/g.

The term “Unit Cell Size” for a material as used herein is defined as the unit cell size as determined by ASTM Specification D 3942. Unless otherwise noted, the unit of measurement used for unit cell size herein is in Angstroms (Å).

An EMY zeolite can exhibit a low volume of pores in the “small mesoporous” range (30 to 50 Å pore diameter) as well as a low “small mesopore peak” of about 0.09 cm³/g in this small mesopore range. Additionally or alternately, there is beneficially a significant “large mesopore peak” associated mainly with the large mesoporous structures (50 to 500 Å pore diameter range) of the EMY zeolite, such as a large mesopore peak of at least about 0.19 cm³/g.

In various aspects, the Large-to-Small Pore Volume Ratio or “LSPVR” of an EMY zeolite can be at least about 4.0, more preferably at least about 5.0, and even more preferably, the LSPVR of the EMY can be at least about 6.0. Additionally or alternately, the “Large-to-Small Pore Volume Ratio” of an EMY can be at least about 10.0, or at least about 12.0, or at least about 15.0 after long-term deactivation steaming at 1400° F. for 16 hours.

EMY zeolites can have a Large Mesopore Volume of at least 0.03 cm³/g, more preferably at least 0.05 cm³/g, and even more preferably at least 0.07 cm³/g. Additionally or alternately, EMY zeolites can have a Small Mesopore Peak of less than about 0.15 cm³/g, or less about 0.13 cm³/g, or less than about 0.11 cm³/g.

First Hydroprocessing Stage—Hydrotreating and/or Hydrocracking

In various aspects, a first hydroprocessing stage can be used to reduce the heteroatom content of a feed and/or to perform a reduced or minimized amount of conversion of the feed.

With regard to heteroatom removal, the conditions in the initial hydroprocessing stage (hydrotreating and/or hydrocracking and/or optional dewaxing) can be sufficient to reduce the sulfur content of the hydroprocessed effluent to about 250 wppm or less, or about 200 wppm or less, or about 150 wppm or less, or about 100 wppm or less, or about 50 wppm or less, or about 25 wppm or less, or about 10 wppm or less, or about 1 wppm to about 250 wppm, or about 1 wppm to about 25 wppm, or about 1 wppm to about 10 wppm, or about 5 wppm to about 250 wppm, or about 5 wppm to about 200 wppm, or about 5 wppm to about 150 wppm, or about 5 wppm to about 100 wppm, or about 5 wppm to about 50 wppm, or about 5 wppm to about 25 wppm, or about 25 wppm to about 250 wppm, or about 25 wppm to about 200 wppm, or about 25 wppm to about 150 wppm, or about 25 wppm to about 100 wppm, or about 25 wppm to about 50 wppm, or about 50 wppm to about 250 wppm, or about 50 wppm to about 200 wppm, or about 50 wppm to about 150 wppm, or about 50 wppm to about 100 wppm. Additionally or alternately, the conditions in the initial hydroprocessing stage can be sufficient to reduce the nitrogen content to about 100 wppm or less, or about 50 wppm or less, or about 25 wppm or less, or about 10 wppm or less, or about 1 wppm to about 100 wppm, or about 1 wppm to about 50 wppm, or about 1 wppm to about 25 wppm, or about 1 wppm to about 10 wppm, or about 10 wppm to about 100 wppm, or about 10 wppm to about 50 wppm, or about 10 wppm to about 25 wppm, or about 25 wppm to about 100 wppm, or about 25 wppm to about 50 wppm.

With regard to feed conversion, in the initial hydroprocessing stage, the hydrotreating and/or hydrocracking conditions can typically be sufficient to attain a relatively low conversion level relative to a conversion temperature of 700° F. (371° C.), e.g., less than less than 45%, less than 40%, from about 5% to about 45%, from about 5% to about 40%, from about 5% to about 30%, from about 5% to about 20%, from about 10% to about 45%, from about 10% to about 40%, from about 10% to about 30%, from about 10% to about 20%, from about 15% to about 45%, from about 15% to about 40%, from about 15% to about 30%, from about 20% to about 45%, from about 20% to about 40%, from about 20% to about 30%, from about 25% to about 45%, or from about 25% to about 40%. The amount of conversion is defined as the wt % of feed boiling above the conversion temperature that is converted to products boiling below the conversion temperature. The amount of conversion includes all conversion across the initial hydroprocessing stage. Thus, if the feedstock is exposed to both a hydrotreating catalyst and a hydrocracking catalyst during the initial hydroprocessing stage, the amount of conversion includes the conversion based on exposure to both catalysts. Additionally, if an optional dewaxing catalyst is included in the initial hydroprocessing stage, the amount of conversion also includes any conversion based on exposure to the dewaxing catalyst.

In aspects that include hydrotreating as part of the initial hydroprocessing stage, the hydrotreating catalyst can comprise any suitable hydrotreating catalyst, e.g., a catalyst comprising at least one Group VIII metal (for example selected from Ni, Co, and a combination thereof) and at least one Group VIB metal (for example selected from Mo, W, and a combination thereof), optionally including a suitable support and/or filler material (e.g., comprising alumina, silica, titania, zirconia, or a combination thereof). The hydrotreating catalyst according to aspects of this invention can be a bulk catalyst or a supported catalyst. Techniques for producing supported catalysts are well known in the art. Techniques for producing bulk metal catalyst particles are known and have been previously described, for example in U.S. Pat. No. 6,162,350, which is hereby incorporated by reference. Bulk metal catalyst particles can be made via methods where all of the metal catalyst precursors are in solution, or via methods where at least one of the precursors is in at least partly in solid form, optionally but preferably while at least another one of the precursors is provided only in a solution form. Providing a metal precursor at least partly in solid form can be achieved, for example, by providing a solution of the metal precursor that also includes solid and/or precipitated metal in the solution, such as in the form of suspended particles. By way of illustration, some examples of suitable hydrotreating catalysts are described in one or more of U.S. Pat. Nos. 6,156,695, 6,162,350, 6,299,760, 6,582,590, 6,712,955, 6,783,663, 6,863,803, 6,929,738, 7,229,548, 7,288,182, 7,410,924, and 7,544,632, U.S. Patent Application Publication Nos. 2005/0277545, 2006/0060502, 2007/0084754, and 2008/0132407, and International Publication Nos. WO 04/007646, WO 2007/084437, WO 2007/084438, WO 2007/084439, and WO 2007/084471, inter alfa.

In aspects that include hydrotreating as part of the initial hydroprocessing stage, the hydrotreating conditions can comprise one or more of: a weight average bed temperature (WABT) from about 550° F. (about 288° C.) to about 800° F. (about 427° C.); a total pressure from about 300 psig (about 2.1 MPag) to about 3000 psig (about 20.7 MPag), for example from about 700 psig (about 4.8 MPag) to about 2000 psig (about 13.8 MPag); an LHSV from about 0.1 hr⁻¹ to about 20 hr⁻¹, for example from about 0.2 hr⁻¹ to about 10 hr⁻¹; and a hydrogen treat gas rate from about 500 scf/bbl (about 85 Nm³/m³) to about 10000 scf/bbl (about 1700 Nm³/m³), for example from about 750 scf/bbl (about 130 Nm³/m³) to about 7000 scf/bbl (about 1200 Nm³/m³) or from about 1000 scf/bbl (about 170 Nm³/m³) to about 5000 scf/bbl (about 850 Nm³/m³).

In aspects that include hydrocracking as part of the initial hydroprocessing stage, the initial stage hydrocracking catalyst can comprise any suitable or standard hydrocracking catalyst, for example, a zeolitic base selected from zeolite Beta, zeolite X, zeolite Y, faujasite, ultrastable Y (USY), dealuminized Y (Deal Y), Mordenite, ZSM-3, ZSM-4, ZSM-18, ZSM-20, ZSM-48, and combinations thereof, which base can advantageously be loaded with one or more active metals (e.g., either (i) a Group VIII noble metal such as platinum and/or palladium or (ii) a Group VIII non-noble metal such nickel, cobalt, iron, and combinations thereof, and a Group VIB metal such as molybdenum and/or tungsten).

In aspects that include hydrocracking as part of the initial hydroprocessing stage, the initial stage hydrocracking conditions can be similar to those for the second stage. Additionally or alternately the hydrocracking conditions in an initial hydrocracking stage can comprise one or more of: a weight average bed temperature (WABT) from about 550° F. (about 288° C.) to about 800° F. (about 427° C.); a total pressure from about 300 psig (about 2.1 MPag) to about 3000 psig (about 20.7 MPag), for example from about 700 psig (about 4.8 MPag) to about 2000 psig (about 13.8 MPag); an LHSV from about 0.1 hr⁻¹ to about 20 hr⁻¹, for example from about 0.2 hr⁻¹ to about 10 hr⁻¹; and a hydrogen treat gas rate from about 500 scf/bbl (about 85 Nm³/m³) to about 10000 scf/bbl (about 1700 Nm³/m³), for example from about 750 scf/bbl (about 130 Nm³/m³) to about 7000 scf/bbl (about 1200 Nm³/m³) or from about 1000 scf/bbl (about 170 Nm³/m³) to about 5000 scf/bbl (about 850 Nm³/m³).

Optionally, if multiple reactors are included in the initial hydroprocessing stage, an intermediate separation can be performed between reactors to remove a gas phase portion of the reactor effluent. This can allow, for example, removal of a portion of the H₂S and NH₃ that can be generated during hydroprocessing of a feedstock with a high sulfur and/or nitrogen content.

Optional Dewaxing

In some aspects, catalytic dewaxing can be performed in the initial stage, in the second stage, or in both stages. Catalytic dewaxing can be performed in a reactor that also includes another catalyst, such as a hydrocracking catalyst, or the catalytic dewaxing can be performed in a separate reactor. As described below, if catalytic dewaxing is performed in fewer than all of the stages, a divided wall column separator can optionally be used to allow for production of more than one type of diesel and/or distillate fuel fraction.

Dewaxing catalysts can be selected from molecular sieves such as crystalline aluminosilicates (zeolites) or silico-aluminophosphates (SAPOs). In an embodiment, the molecular sieve can be a 1-D or 3-D molecular sieve. In an embodiment, the molecular sieve can be a 10-member ring 1-D molecular sieve. In an aspect, the molecular sieve can comprise, consist essentially of, or be ZSM-22, ZSM-23, ZSM-35, and/or ZSM-48. Optionally but preferably, molecular sieves that are selective for dewaxing by isomerization as opposed to cracking can be used, such as ZSM-48, ZSM-23, or a combination thereof. Additionally or alternately, the molecular sieve can comprise, consist essentially of, or be a 10-member ring 1-D molecular sieve, such as EU-2, EU-11, ZBM-30, ZSM-48, or ZSM-23. ZSM-48 is most preferred. Note that a zeolite having the ZSM-23 structure with a silica to alumina ratio of from about 20:1 to about 40:1 can sometimes be referred to as SSZ-32. Preferably, the dewaxing catalysts used in processes according to the invention can be catalysts with a low ratio of silica to alumina. For example, for ZSM-48, the ratio of silica to alumina in the zeolite can be about 100:1 or less, such as about 90:1 or less, or about 75:1 or less, or about 70:1 or less. Additionally or alternately, the ratio of silica to alumina in the ZSM-48 can be at least about 50:1, such as at least about 60:1, or at least about 65:1.

The dewaxing catalyst can also include a metal hydrogenation component, such as a Group VIII metal (Groups 8-10 of IUPAC periodic table). Suitable Group VIII metals can include Pt, Pd, or Ni. Preferably the Group VIII metal is a noble metal, such as Pt, Pd, or a combination thereof. The dewaxing catalyst can include at least about 0.03 wt % of a Group VIII metal, such as at least about 0.05 wt %, or preferably at least about 0.1 wt %. Additionally or alternately, the dewaxing catalyst can include about 0.35 wt % or less of a Group VIII metal, such as about 0.3 wt % or less.

In various embodiments, the catalysts according to the invention further include a metal hydrogenation component. The metal hydrogenation component is typically a Group VI and/or a Group VIII metal. Preferably, the metal hydrogenation component can be a combination of a non-noble Group VIII metal with a Group VI metal. Suitable combinations can include Ni, Co, or Fe with Mo or W, preferably Ni with Mo or W. The metal hydrogenation component may be added to the catalyst in any convenient manner.

The amount of metal in the catalyst can be at least 0.1 wt % based on catalyst, or at least 0.5 wt %, or at least 1.0 wt %, or at least 2.5 wt %, or at least 5.0 wt %, based on catalyst. The amount of metal in the catalyst can be 20 wt % or less based on catalyst, or 10 wt % or less, or 5 wt % or less, or 2.5 wt % or less, or 1 wt % or less. For embodiments where the metal is a combination of a non-noble Group VIII metal with a Group VI metal, the combined amount of metal can be from 0.5 wt % to 20 wt %, or 1 wt % to 15 wt %, or 2.5 wt % to 10 wt %.

Optionally, the dewaxing catalyst can include a binder for the molecular sieve, such as alumina, titania, silica, silica-alumina, zirconia, or a combination thereof In a preferred embodiment, the binder can be alumina. In another embodiment, the binder can be alumina, titania, or a combination thereof. In still another embodiment, the binder can be titania, silica, zirconia, or a combination thereof. Optionally, the binder can correspond to a binder with a relatively high surface area. One way to characterize the surface of the binder is in relation to the surface area of the molecular sieve in the dewaxing catalyst. For example, the ratio of molecular sieve surface area to binder surface can be about 80 to 100 or less, such as about 70 to 100 or less or about 60 to 100 or less.

Catalytic dewaxing can be performed by exposing a feedstock to a dewaxing catalyst under effective (catalytic) dewaxing conditions. Effective dewaxing conditions can include a temperature of at least about 500° F. (˜260° C.), at least about 550° F. (˜288° C.), at least about 600° F. (˜316° C.), or at least about 650° F. (˜343° C.). Alternatively, the temperature can be about 750° F. (˜399° C.) or less, about 700° F. (˜371° C.) or less, or about 650° F. (˜343° C.) or less. The pressure can be at least about 200 psig (˜1.4 MPa), at least about 500 psig (˜3.4 MPa), at least about 750 psig (˜5.2 MPa), or at least about 1000 psig (˜6.9 MPa). Alternatively, the pressure can be about 1500 psig (˜10.3 MPa) or less, about 1200 psig (˜8.2 MPa) or less, about 1000 psig (˜6.9 MPa) or less, or about 800 psig (˜5.5 MPa) or less. The Liquid Hourly Space Velocity (LHSV) can be at least about 0.5 hr⁻¹, or at least about 1.0 hr⁻¹, or at least about 1.5 hr⁻¹. Alternatively, the LHSV can be about 5.0 hr⁻¹ or less, or about 3.0 hr⁻¹ or less, or about 2.0 hr⁻¹ or less. The treat gas rate can be at least about 500 scf/bbl (˜85 Nm³/m³), at least about 750 scf/bbl (˜128 Nm³/m³), or at least about 1000 scf/bbl (˜170 Nm³/m³). Alternatively, the treat gas rate can be about 4000 scf/bbl (˜680 Nm³/m³) or less, about 2000 scf/bbl (˜340 Nm³/m³) or less, about 1500 scf/bbl (˜255 Nm³/m³) or less, or about 1250 scf/bbl (˜213 Nm³/m³) or less.

Based on dewaxing under effective catalytic dewaxing conditions, the cloud point of a dewaxed distillate fuel fraction can be reduced relative to the feedstock by at least about 10° F. (˜5° C.), such as at least about 20° F. (˜11° C.) or at least about 30° F. (˜17° C.). Additionally or alternately, in an aspect where the feedstock is hydrotreated prior to dewaxing, the cloud point of a dewaxed distillate fuel fraction can be reduced relative to the hydrotreated effluent by at least about 10° F. (˜5° C.), such as at least about 20° F. (˜11° C.) or at least about 30° F. (˜17° C.). The amount of cloud point reduction can depend on a variety of factors, including the sulfur content of the feedstock, the nitrogen content of the feedstock, and the selected effective dewaxing conditions.

Fractionation of First and Second Stage Effluents

In various aspects, the systems and processes described herein can be used to hydroprocess a feed to form distillate fuels with improved yield and/or improved properties. Producing an improved yield of distillate fuels can include an improved yield for a process that converts substantially all of a feed to compounds suitable for inclusion in a diesel/distillate fuel.

The products generated by fractionation of the effluents from the hydroprocessing stage and the hydrocracking stage can correspond to, for example, one or more diesel boiling range fractions, one or more naphtha boiling range fractions, a bottoms fraction, and a light ends fraction. Optionally, one or more kerosene boiling range fractions can also be produced. In some aspects the distillation cut point between the bottoms fraction and the highest boiling diesel boiling range fraction can be set at any convenient value, depending on the desired diesel quality.

In such aspects, the bottoms fraction can have a T5 boiling point of at least about 600° F. (˜316° C.), at least about 650° F. (˜343° C.), at least about 700° F. (˜371° C.), or at least about 750° F. (˜399° C.). In other aspects, the bottoms fraction can correspond to a distillate fraction. In such aspects, the bottoms fraction can have a T5 boiling point of about 300° F. (˜149° C.) to about 650° F. (˜343° C.) or about 350° F. (˜177° C.) to about 450° F. (˜232° C.).

In various aspects, it may be desirable to use a portion of a hydroprocessed effluent and/or hydrocracked effluent as a feed for the hydrocracking stage containing a noble metal hydrocracking catalyst while forming a distillate boiling range product from a second portion of the hydroprocessed effluent and/or hydrocracked effluent. For example, when the bottoms fraction corresponds to a distillate boiling range fraction, this type of separation may be performed on a bottoms fraction from a fractionator. As another example, a fractionator may produce a fuels boiling range fraction that contains both a naphtha boiling range portion and a distillate boiling range portion. This type of separation may be performed on such a fuels boiling range fraction.

Various configurations are available for fractionating the effluents to separate distillate fuel products and/or naphtha fuel products from the remaining portions of an effluent. One option can be to have a separate fractionator and/or other separation stage for each hydroprocessing/hydrocracking stage. Although a single fractionator can be convenient in some circumstances, a plurality of separators could also be used as a separation stage to form various fractions. In this type of configuration, the fractionator for the first hydroprocessing stage can be different from the fractionator for the second hydrocracking stage.

Another option can be to use a common fractionator for both stages. In this type of configuration, the effluent from both the first hydroprocessing stage and the second hydrocracking stage can be passed into the same fractionator/separation stage. The bottoms from the fractionator can be used as the input feed for the second hydrocracking stage. In this type of configuration, a single fraction of each fractionated product can be produced. The fractionation can be performed (for example) to form one or more diesel boiling range fractions, one or more kerosene boiling range fractions, one or more naphtha boiling range fractions, a bottoms fraction, and a light ends fraction.

Still another option can be to use a divided wall column as a fractionation tower. The divided wall column can contain at least three separate volumes. One of the volumes is a common volume, typically located toward the top of the divided wall column. The remaining volumes in the divided wall column can represent volumes separated from each other by a dividing wall. The various volumes are all in fluid communication with each other via the common volume. However, petroleum fractions with a sufficiently high boiling point should not be able to travel up the column to a sufficient height to reach the common volume, thus effectively fractionating the petroleum fractions by boiling point.

The dividing wall can have a height that is tall enough to allow for removal of two or more fractions from a separated volume within the column. This means that at least two fractions that do not mix with the common volume can be removed from a separated area. For example, a separated volume could be used to produce both a bottoms stream and a diesel stream that are withdrawn from the separated volume at a location below the height of the dividing wall. Optionally, the dividing wall can have a height that is sufficient to allow for removal of two or more fractions from each of the separated volumes, or removal of three or more fractions from each of the separated volumes.

Additionally or alternatively, the height of the dividing wall can be selected based on controlling the amount of contamination between the multiple product fractions produced by the column. For example, in a divided wall column that produces diesel fractions, the separated volumes can be used to produce two diesel fractions of different quality, such as diesel fractions having different cloud points. This can be the result, for example, of including a dewaxing catalyst in only the second hydrocracking stage of the process configuration.

Fuel Fraction Yield and Properties

The fuel fraction(s) produced according to the methods described herein can have an improved yield and/or improved properties relative to distillate fraction(s) produced according to conventional methods.

With regard to distillate fuel yield, the total yield of distillate fuel boiling range products can be at least about 88 vol % relative to the volume of the ˜400° F.+(˜204° C.+) portion of the feed, e.g., at least about 90 vol %, at least about 92 vol %, such as up to about 100 vol % or more. This additional distillate yield can be partially the result of lower naphtha yield and partially the result of reduced production of light ends. As a result, the total fuels yield and/or total C₆₊ yield can also be greater when using the processes described herein. For example, the total fuels yield, corresponding to the naphtha yield plus the distillate fuel yield, can be at least about 110 vol % relative to the volume of the ˜400° F.+(˜204° C.+) portion of the feed, e.g., at least about 112 vol %, such as up to about 120 vol %. Additionally or alternatively, the C₆₊ yield can be at least about 108 vol % of the volume of the ˜400° F.+(˜204° C.+) portion of the feed, or at least about 110 vol %, e.g., at least about 112 vol %, such as up to about 120 vol %.

Additionally or alternatively, the distillate fraction can have a cetane index (ASTM D4737) of at least about 50, e.g., at least about 55, at least about 58, or at least about 60. For example, the distillate fraction can have a cetane index of about 50 to about 70, such as about 50 to about 65, about 50 to about 60, about 55 to about 70, about 55 to about 65, about 55 to about 60, about 58 to about 70, or about 58 to about 65. In particular, the distillate fraction can have a cetane index of at least about 50, such as about 50 to about 65, about 50 to about 60, or about 55 to about 60. Additionally or alternately, the distillate fraction can have an API gravity of at least about 33.0, e.g., at least about 35.0 or at least about 37.0, such as up to about 42.0 or more.

Still another property that can be characterized is the aromatics content of the distillate fraction. As noted above, the processes described herein can be suitable for processing of challenged feeds, such as feeds having an initial aromatics content of at least about 50 wt %. In various aspects, the aromatics content of the distillate boiling range fraction of the effluent can be about 20 wt % or less, about 10 wt % or less, about 5 wt % or less, or about 2 wt % or less, such as down to about 1 wt % or even lower. For example, the aromatics content of the distillate boiling range fraction of the effluent can be about 0.1 wt % to about 20 wt %, such as about 0.1 wt % to about 10 wt %, about 0.1 wt % to about 5 wt %, about 0.1 wt % to about 2 wt %, about 0.1 wt % to about 1 wt %, about 1 wt % to about 20 wt %, about 1 wt % to about 10 wt %, about 1 wt % to about 5 wt %, about 5 wt % to about 20 wt %, about 5 wt % to about 10 wt %, or about 10 wt % to about 20 wt %. In particular, the aromatics content of the distillate boiling range fraction of the effluent can be about 0.1 wt % to about 20 wt %, about 1 wt % to about 20 wt %, or about 10 wt % to about 20 wt %. Without being bound by any particular theory, it is believed that the noble metal USY catalyst in the hydrocracking stage can allow for improved aromatic saturation, which can allow for production of distillate fuels with reduced aromatics content and/or increased cetane index when processing a challenged feed.

Yet another property that can be characterized is the naphthene content of the distillate fraction. In various aspects, the naphthene content of the distillate boiling range fraction can be at least about 50 wt %, e.g., at least about 55 wt %, at least about 60 wt %, or at least about 65 wt %. For example, the naphthene content can be about 50 wt % to about 80 wt %, such as about 50 wt % to about 70 wt %, about 55 wt % to about 80 wt %, about 55 wt % to about 80 wt %, about 55 wt % to about 70 wt %, about 60 wt % to about 80 wt %, about 60 wt % to about 70 wt %, or about 65 wt % to about 80 wt %. In particular, the naphthene content of the distillate boiling range fraction can be at least about 50 wt %, for example, about 50 wt % to about 80 wt %, about 60 wt % to about 80 wt %, or about 60 wt % to about 70 wt %.

Additional Embodiments

Embodiment 1. A method for producing a fuel product fraction, comprising: hydroprocessing a feedstock having a T95 boiling point of about 850° F. (˜454° C.) or less under first hydroprocessing conditions to form a hydroprocessed effluent, the feedstock having an aromatics content of at least about 40 wt % (or at least about 50 wt %) and a cetane index of about 35 or less (such as about 30 or less or about 25 or less); fractionating at least a portion of the hydroprocessed effluent to form at least a first fraction and a second fraction, the second fraction having a T5 boiling point of at least about 600° F. (˜316° C.), or at least about 650° F. (˜343° C.); hydrocracking at least a first portion of the second fraction in the presence of hydrocracking catalyst under second hydrocracking conditions to form a hydrocracked effluent, the hydrocracking catalyst comprising USY zeolite having a unit cell size of about 24.30 Å or less, a silica to alumina ratio of at least about 50, and an Alpha value of about 20 or less, the hydrocracking catalyst further comprising about 0.1 wt % to about 5.0 wt % of a Group 8-10 noble metal supported on the hydrocracking catalyst; and fractionating at least a portion of the hydrocracked effluent to form at least a third fraction, wherein the first fraction, the third fraction, or a combination thereof comprise a distillate boiling range product having an aromatics content of about 20 wt % or less (such as about 10 wt % or less or about 5 wt % or less) and a cetane index of at least about 50 (such as at least about 55 or at least about 58), the distillate boiling range product optionally having a naphthene content of at least about 50 wt % (such as at least about 55 wt % or at least about 60 wt %).

Embodiment 2. The method of Embodiment 1, wherein fractionating at least a portion of the hydrocracked effluent further comprises forming a fourth fraction having a T5 boiling point of at least about 600° F. (316° C.), or at least about 650° F. (343° C.), and wherein hydrocracking at least a first portion of the second fraction further comprises hydrocracking at least a portion of the fourth fraction.

Embodiment 3. A method for producing a fuel product fraction, comprising:

hydroprocessing a feedstock having a T95 boiling point of about 850° F. (˜454° C.) or less under first hydroprocessing conditions to form a hydroprocessed effluent, the feedstock having an aromatics content of at least about 40 wt % (or at least about 50 wt %) and a cetane index of about 35 or less (such as about 30 or less or about 25 or less); fractionating at least a portion of the hydroprocessed effluent to form at least a first fraction and a second fraction, the first fraction having a lower T5 boiling point than the second fraction, the second fraction having a T5 boiling point of about 300° F. (˜149° C.) to about 650° F. (˜343° C.), such as about 350° F. (˜177° C.) to about 450° F. (˜232° C.); hydrocracking at least a first portion of the second fraction in the presence of a hydrocracking catalyst under second hydrocracking conditions to form a hydrocracked effluent, the hydrocracking catalyst comprising USY zeolite having a unit cell size of about 24.30 Å or less, a silica to alumina ratio of at least about 50, and an Alpha value of about 20 or less, the hydrocracking catalyst further comprising about 0.1 wt % to about 5.0 wt % of a Group 8-10 noble metal supported on the hydrocracking catalyst; and fractionating at least a portion of the hydrocracked effluent to form at least a third fraction and a fourth fraction, the third fraction having a lower T5 boiling point than the fourth fraction, the fourth fraction having a T5 boiling point of about 350° F. (˜177° C.) to about 650° F. (˜343° C.), such as about 350° F. (˜177° C.) to about 450° F. (˜232° C.), wherein the second fraction, the fourth fraction, or a combination thereof comprise a distillate boiling range product having a combined aromatics content of about 20 wt % or less (such as 10 wt % or less or about 5 wt % or less) and a cetane index of at least about 50 (such as at least about 55 or at least about 58), the distillate boiling range product optionally having a naphthene content of at least about 50 wt % (such as at least about 55 wt % or at least about 60 wt %).

Embodiment 4. The method of Embodiment 3, wherein hydrocracking at least a first portion of the second fraction comprises hydrocracking at least a first portion of the second fraction and hydrocracking at least a portion of the fourth fraction.

Embodiment 5. The method of any of the above embodiments, the method further comprising a) separating the distillate boiling range product from the first fraction, the third fraction, or the combination thereof, or b) separating the distillate boiling range product from the second fraction, the fourth fraction, or the combination thereof.

Embodiment 6. The method of any of Embodiments 2-5, wherein c) the fractionation of the at least a portion of the hydroprocessed effluent and the fractionation of the at least a portion of the hydrocracked effluent are performed in a divided wall column fractionator, the second fraction being different from the fourth fraction, or d) the fractionation of the at least a portion of the hydroprocessed effluent and the fractionation of the at least a portion of the hydrocracked effluent are performed in a common fractionator, the second fraction and the fourth fraction being the same fraction.

Embodiment 7. The method of any of the above embodiments, wherein the feedstock has an API gravity of about 20.0 or less (such as about 18.0 or less), and wherein the distillate boiling range product has an API gravity of at least about 33.0 (such as at least about 35.0 or at least about 37.0).

Embodiment 8. The method of any of the above embodiments, wherein the feedstock has a sulfur content of at least about 1.0 wt % (such as at least about 2.0 wt %), wherein the feedstock has a T95 boiling point of about 800° F. (˜427° C.) or less, or a combination thereof

Embodiment 9. The method of any of the above embodiments, wherein the hydrocracking catalyst comprises a USY zeolite having one or more or a unit cell size of about 24.24 Å or less, a silica to alumina ratio of at least about 85, and an Alpha value of about 10 or less, wherein optionally the USY zeolite comprises a Meso-Y zeolite, an Extra Mesoporous Y zeolite, or a combination thereof.

Embodiment 10. The method of any of the above embodiments, wherein hydroprocessing the feedstock comprising exposing the feedstock to a hydrotreating catalyst under hydrotreating conditions, or wherein hydroprocessing the feedstock comprises exposing the feedstock to a second hydrocracking catalyst under second hydrocracking conditions, or a combination thereof.

Embodiment 11. The method of any of the above embodiments, the method further comprising exposing the hydrocracked effluent to a dewaxing catalyst under dewaxing conditions to form a hydrocracked, dewaxed effluent.

Embodiment 12. The method of any of the above embodiments, wherein a yield of the distillate boiling range product is at least about 88 vol % relative to a ˜400° F.+(˜204° C.+) portion of the feedstock (such as at least about 90 vol %).

Embodiment 13. The method of any of the above embodiments, wherein fractionating the at least a portion of the hydroprocessed effluent and the at least a portion of the hydrocracked effluent comprises forming a naphtha boiling range product, at least one of the first fraction and the third fraction optionally comprising the naphtha boiling range product, a combined yield of the naphtha boiling range fraction and the distillate boiling range product being at least about 110 vol % relative to the ˜400° F.+(˜204° C.+) portion of the feedstock, and wherein optionally a C₆₊ yield is at least about 108 vol % relative to the ˜400° F.+(˜204° C.+) portion of the feedstock.

Embodiment 14. A distillate boiling range product formed according to the method of any of the above embodiments.

Embodiment 15. A distillate boiling range product having a cetane index of at least about 50 (such as at least about 55 or at least about 58), an aromatics content of about 10 wt % or less, a naphthene content of at least about 50 wt %, a sulfur content of about 10 wppm or less, and an API gravity of at least about 35.

Embodiment 16. A system for producing a fuel product fraction, comprising: a hydrotreating reactor comprising a hydrotreating feed inlet, a hydrotreating effluent outlet, and at least one fixed catalyst bed of a hydrotreating catalyst; a separation stage having a first separation stage inlet and a second separation stage inlet, the first separation stage inlet being in fluid communication with the hydrotreating effluent outlet, the separation stage further comprising a plurality of separation stage liquid effluent outlets, one or more of the separation stage liquid effluent outlets corresponding to product outlets; and a hydrocracking reactor comprising a hydrocracking feed inlet, a hydrocracking effluent outlet, and at least one fixed catalyst bed of a hydrocracking catalyst, the hydrocracking feed inlet being in fluid communication with at least one separation stage liquid effluent outlet, the hydrocracking effluent outlet being in fluid communication with the second separation stage inlet of the separation stage, and the hydrocracking catalyst comprising USY zeolite having a unit cell size of about 24.30 Å or less, a silica to alumina ratio of at least about 50, and an Alpha value of about 20 or less, the hydrocracking catalyst further comprising about 0.1 wt % to about 5.0 wt % of a Group 8-10 noble metal supported on the hydrocracking catalyst.

Embodiment 17. The system of Embodiment 16, wherein the separation stage comprises a divided wall column fractionator, the first separation stage inlet being different from the second separation stage inlet, the one or more product outlets being different from the at least one separation stage liquid effluent outlet in fluid communication with the hydrocracking feed inlet.

Embodiment 18. The system of Embodiment 16 or 17, wherein the separation stage comprises a common fractionator, the first separation stage inlet and the second separation stage inlet optionally comprising the same inlet.

Embodiment 19. The system of any of Embodiments 16-18, the system further comprising an additional hydrocracking reactor comprising an additional hydrocracking feed inlet, an additional hydrocracking effluent outlet, and at least one fixed catalyst bed of an additional hydrocracking catalyst, the additional hydrocracking reactor providing indirect fluid communication between the hydrotreating effluent outlet and the first separation stage inlet, the additional hydrocracking feed inlet being in fluid communication with the hydrotreating effluent outlet, the additional hydrocracking effluent outlet being in fluid communication with the first separation stage inlet.

EXAMPLES Example 1 Distillate Yield

To demonstrate the benefits of processes as described herein, processing of a challenged feed was modeled for three different reaction system configurations using an empirical-based model. The three different modeled configurations can be understood with reference to the general configuration shown in FIG. 1. In the initial stage in Configuration I, a first reactor (such as reactor 110) included a commercially available NiMo supported hydrotreating catalyst. A second reactor in the initial stage (such as a reactor 120) included a commercially available NiMo hydrocracking catalyst. The effluent from the final reactor in the initial stage (such as reactor 120) was then passed into a fractionator. The bottoms from the fractionator was then further processed in a second stage hydrocracking reactor (such as reactor 140) that also included the commercially available NiMo hydrocracking catalyst. The effluent from the second stage hydrocracking reactor was returned to the fractionator. In Configuration II, the reactors in the initial stage were similar to Configuration I, while the second stage hydrocracking reactor included a noble metal USY catalyst. The noble metal USY catalyst included USY with a unit cell size of less than about 24.30 Å, a silica to alumina ratio of greater than about 50, and an alpha value of about 20 or less. The noble metal USY catalyst further included about 1.0 wt % of Pt, based on the weight of the support. In Configuration III, the initial stage included a hydrotreating reactor (such as reactor 110) that contained the commercially available NiMo supported hydrotreating catalyst. The effluent from the hydrotreating reactor was passed to the fractionator. In other words, optional reactor 120 was not used in configuration III. Reactor 140 included the noble metal USY catalyst.

In the model, all of the reactors were operated at about 1550-1600 psig (˜11 MPa). The first hydrotreating reactor was operated at about 630° F. (˜332° C.). Hydrocracking reactors containing a conventional NiMo catalyst were modeled at a temperature of about 705° F. (˜374° C.). Reactors containing the noble metal USY catalysts were modeled at a temperature of about 580° F. (˜304° C.). In Configurations I and II, the LHSV was about 1.4 hr⁻¹ in the hydrotreating reactor, about 3.3 hr⁻¹ in the first stage hydrocracking reactor, and about 1.8 hr⁻¹ in the second stage hydrocracking reactor. In Configuration III, the LHSV was about 1.0 hr⁻¹ in the hydrotreating reactor and about 1.8 hr⁻¹ in the hydrocracking reactor.

Table 1 shows the feed used for modeling of processing in Configurations I, II, and III. It is noted that “FBP” refers to final boiling point.

TABLE 1 Feed Properties Hydrogen Content (wt %) ~9.6 Carbon Aromaticity (wt %) ~56.0 API Gravity ~16.3 Specific Gravity @ 60° F. ~0.96 Total Sulfur (wt %) ~3.1 Total Nitrogen (wppm) ~700 Total Aromatics (wt %) ~76 Cetane Index D4737 ~23 D2887 5 wt % (° F.) ~409 D2887 95 wt % (° F.) ~716 D2887 FBP (° F.) ~785

The feed shown in Table 1 represents a challenged feed for production of distillate fuels. The boiling range of the feed roughly corresponds to the diesel range, but the cetane index for the feed (˜23) is lower than desirable for a distillate fuel. This may be due in part to the relatively high aromatics content (76 wt %) for the feed.

Table 2 shows the modeled relative product yields from processing the feed in Table 1 according to Configurations I, II, and III. In Table 2, the “distillate” yield refers to a combination of jet and diesel yield, corresponding to a boiling range of ˜315° F. (˜157° C.) to ˜800° F. (˜427° C.).

TABLE 2 Product Yields Configuration I Configuration II Configuration III C₁-C₄ (scf/B) ~76 ~59.5 ~30.3 Naphtha (vol %) ~23.2 ~21.9 ~20.6 Distillate (vol %) ~86.7 ~89.9 ~92.0 Total C₆₊ (vol %) ~107.6 ~110.7 ~112.3

As shown in Table 2, using a noble metal USY catalyst with unit cell size of less than about 24.30 Å, silica to alumina ratio of at least about 50, and an alpha value of less than about 20 in the second hydrocracking stage can provide a substantial improvement in distillate yield relative to using a commercially available base metal hydrocracking catalyst in the second hydrocracking stage. In addition to increasing the distillate yield, the volume of light ends can be reduced relative to using the commercially available base metal hydrocracking catalyst. The total volume of C₆₊ compounds can also be improved.

Table 2 also appears to show that further yield improvements can be obtained by limiting the amount of conversion that occurs in the initial hydroprocessing stage. In Configuration C, the initial hydroprocessing stage only included hydrotreatment of the feed, resulting in lower conversion of the feed relative to ˜700° F. (˜371° C.). As a result, additional hydrocracking was performed in the second hydrocracking stage in the presence of the noble metal USY catalyst. This resulted in still further improvements in the distillate yield and the total C⁶⁻ yield.

Example 2 Characterization of a Distillate Fraction

A challenged feed that was primarily composed of distillate boiling range compounds was processed using two configurations (Configurations IV and V) that can be understood relative to the configuration shown in FIG. 2. The distillate boiling range feed was a challenged feed with an estimated low cetane index of about 23. This is believed to be due to a high aromatics content in the feed. Estimates of additional properties of the feed “A” are shown in FIG. 3.

In the initial stage in Configuration IV, the distillate boiling range feed “A” was introduced into the first reactor (such as reactor 110) that included a commercially available NiMo supported hydrotreating catalyst. A second reactor in the initial stage (such as a reactor 120) included a commercially available NiMo hydrocracking catalyst. The effluent from the final reactor in the initial stage (such as reactor 120) was then passed into a fractionator. A portion of the bottoms from the fractionator was withdrawn as a distillate product “B”. The remaining portion of the bottoms from the fractionator was then further processed in a second stage hydrocracking reactor (such as reactor 140) that also included the commercially available NiMo hydrocracking catalyst. The effluent from the second stage hydrocracking reactor was returned to the fractionator. The reactor conditions for Configuration IV were similar to the conditions modeled for Configuration I.

As shown in FIG. 3, the sulfur content of the distillate product “B” was about 200 wppm. In order to demonstrate the benefits of sweet service processing (Configuration V), distillate product “B” was then exposed to mild hydrotreating conditions to form a hydrotreated effluent “C”. The mild hydrotreating conditions were selected to be sufficient to reduce the sulfur content to less than about 15 wppm. Hydrotreated effluent “C” was then passed into a hydrocracking reactor that included a noble metal USY catalyst. The noble metal USY catalyst was a USY catalyst with a unit cell size of less than about 24.30 Å, a silica to alumina ratio of greater than about 50, and an alpha value of about 20 or less. The noble metal USY catalyst further included about 1.0 wt % of Pt, based on the weight of the support. The reaction conditions in the hydrocracking reactor were an inlet pressure of about 11 MPa-g, a temperature of about 304° C., and a LHSV of about 1.8 hr⁻¹. The hydrocracked effluent was passed into a fractionator which resulted in a naphtha boiling range product (along with light ends) and a bottoms product in the distillate boiling range. A portion of the bottoms product was withdrawn as distillate product “D”, while the remaining portion of the bottoms product was returned to the hydrocracking reactor containing the noble metal USY catalyst.

It is noted that based on the nature of Configuration V, all of the distillate product “D” corresponds to distillate boiling range product that has been exposed to the noble metal USY catalyst. In a commercial setting, a more typical configuration may correspond to the configuration shown in either FIG. 1 or FIG. 2, so that at least a portion of the final distillate product would not be exposed to noble metal USY catalyst. To reflect the type of distillate product that would be expected from a more typical configuration, product “E” in FIG. 3 represents a 50/50 wt % blend of hydrotreated effluent “C” and product “D”.

FIG. 3 appears to show that using a noble metal USY catalyst as described herein in the second hydrocracking stage can allow for production of a distillate fraction with a reduced/minimized aromatic content, even though the feed started with a substantial aromatics content. This can be in contrast to using a conventional NiMo hydrocracking catalyst in the second hydrocracking stage, which can allow a substantial fraction of aromatics to remain in the distillate product. For example, distillate product “B” still had a total aromatics content of about 54 wt % after hydrocracking with the NiMo catalyst. Additional hydrotreating to reduce the sulfur content to less than about 15 wppm (hydrotreated effluent “C”) still only resulted in a total aromatics content of about 39 wt %. By contrast, after additional hydrocracking with the noble metal USY catalyst, the aromatics content of product “E” was reduced to about 20 wt % or less. As shown in the modeling in Example 1, it is believed that this lower aromatics content can be achieved while also increasing the yield of distillate boiling range fuels products and/or total fuels boiling range products. (It is noted that the apparent increase in boiling range between hydrotreated effluent “C” and distillate product “D” was believed to be due to additional fractionation to remove lower boiling compounds.)

When numerical lower limits and numerical upper limits are listed herein, ranges from any lower limit to any upper limit are contemplated. While the illustrative embodiments of the invention have been described with particularity, it will be understood that various other modifications will be apparent to and can be readily made by those skilled in the art without departing from the spirit and scope of the invention. Accordingly, it is not intended that the scope of the claims appended hereto be limited to the examples and descriptions set forth herein but rather that the claims be construed as encompassing all the features of patentable novelty which reside in the present invention, including all features which would be treated as equivalents thereof by those skilled in the art to which the invention pertains.

The present invention has been described above with reference to numerous embodiments and specific examples. Many variations will suggest themselves to those skilled in this art in light of the above detailed description. All such obvious variations are within the full intended scope of the appended claims. 

1. A method for producing a fuel product fraction, comprising: hydroprocessing a feedstock having a T95 boiling point of about 850° F. (˜454° C.) or less under first hydroprocessing conditions to form a hydroprocessed effluent, the feedstock having an aromatics content of at least about 40 wt % and a cetane index of about 35 or less; fractionating at least a portion of the hydroprocessed effluent to form at least a first fraction and a second fraction, the second fraction having a T5 boiling point of at least about 600° F. (˜316° C.); hydrocracking at least a first portion of the second fraction in the presence of hydrocracking catalyst under second hydrocracking conditions to form a hydrocracked effluent, the hydrocracking catalyst comprising USY zeolite having a unit cell size of about 24.30 Å or less, a silica to alumina ratio of at least about 50, and an Alpha value of about 20 or less, the hydrocracking catalyst further comprising about 0.1 wt % to about 5.0 wt % of a Group 8-10 noble metal supported on the hydrocracking catalyst; and fractionating at least a portion of the hydrocracked effluent to form at least a third fraction, wherein the first fraction, the third fraction, or a combination thereof comprise a distillate boiling range product having an aromatics content of about 20 wt % or less and a cetane index of at least about
 50. 2. The method of claim 1, wherein fractionating at least a portion of the hydrocracked effluent further comprises forming a fourth fraction having a T5 boiling point of at least about 600° F. (˜316° C.), and wherein hydrocracking at least a first portion of the second fraction further comprises hydrocracking at least a portion of the fourth fraction.
 3. The method of claim 2, wherein the fractionation of the at least a portion of the hydroprocessed effluent and the fractionation of the at least a portion of the hydrocracked effluent are performed in a divided wall column fractionator, the second fraction being different from the fourth fraction.
 4. The method of claim 2, wherein the fractionation of the at least a portion of the hydroprocessed effluent and the fractionation of the at least a portion of the hydrocracked effluent are performed in a common fractionator, the second fraction and the fourth fraction being the same fraction.
 5. The method of claim 1, the method further comprising: separating the distillate boiling range product from the first fraction, the third fraction, or the combination thereof.
 6. The method of claim 1, wherein the feedstock has an API gravity of about 20.0 or less, and wherein the distillate boiling range product has an API gravity of at least about 33.0.
 7. The method of claim 1, wherein the hydrocracking catalyst comprises a USY zeolite having one or more or a unit cell size of about 24.24 Å or less, a silica to alumina ratio of at least about 85, and an Alpha value of about 10 or less.
 8. The method of claim 1, wherein the USY zeolite comprises a Meso-Y zeolite, an Extra Mesoporous Y zeolite, or a combination thereof.
 9. The method of claim 1, wherein hydroprocessing the feedstock comprising exposing the feedstock to a hydrotreating catalyst under hydrotreating conditions, or wherein hydroprocessing the feedstock comprises exposing the feedstock to a second hydrocracking catalyst under second hydrocracking conditions, or a combination thereof.
 10. The method of claim 1, the method further comprising exposing the hydrocracked effluent to a dewaxing catalyst under dewaxing conditions to form a hydrocracked, dewaxed effluent.
 11. The method of claim 1, wherein a yield of the distillate boiling range product is at least about 88 vol % relative to a ˜400° F.+(˜204° C.+) portion of the feedstock.
 12. The method of claim 1, wherein fractionating the at least a portion of the hydroprocessed effluent and the at least a portion of the hydrocracked effluent comprises forming a naphtha boiling range product, at least one of the first fraction and the third fraction optionally comprising the naphtha boiling range product, a combined yield of the naphtha boiling range fraction and the distillate boiling range product being at least about 110 vol % relative to the ˜400° F.+(˜204° C.+) portion of the feedstock.
 13. The method of claim 12, wherein a C₆₊ yield is at least about 108 vol % relative to the ˜400° F.+(˜204° C.+) portion of the feedstock.
 14. The method of claim 1, wherein the distillate boiling range product has a naphthene content of at least about 50 wt %.
 15. A method for producing a fuel product fraction, comprising: hydroprocessing a feedstock having a T95 boiling point of about 850° F. (˜454° C.) or less under first hydroprocessing conditions to form a hydroprocessed effluent, the feedstock having an aromatics content of at least about 40 wt % and a cetane index of about 35 or less; fractionating at least a portion of the hydroprocessed effluent to form at least a first fraction and a second fraction, the first fraction having a lower T5 boiling point than the second fraction, the second fraction having a T5 boiling point of about 300° F. (˜149° C.) to about 650° F. (˜343° C.); hydrocracking at least a first portion of the second fraction in the presence of a hydrocracking catalyst under second hydrocracking conditions to form a hydrocracked effluent, the hydrocracking catalyst comprising USY zeolite having a unit cell size of about 24.30 Å or less, a silica to alumina ratio of at least about 50, and an Alpha value of about 20 or less, the hydrocracking catalyst further comprising about 0.1 wt % to about 5.0 wt % of a Group 8-10 noble metal supported on the hydrocracking catalyst; and fractionating at least a portion of the hydrocracked effluent to form at least a third fraction and a fourth fraction, the third fraction having a lower T5 boiling point than the fourth fraction, the fourth fraction having a T5 boiling point of about 350° F. (˜177° C.) to about 650° F. (˜343° C.), wherein the second fraction, the fourth fraction, or a combination thereof comprise a distillate boiling range product having a combined aromatics content of about 20 wt % or less and a cetane index of at least about
 50. 16. The method of claim 15, wherein the second fraction has a T5 boiling point of about 300° F. (˜149° C.) to about 450° F. (˜232° C.).
 17. The method of claim 15, wherein hydrocracking at least a first portion of the second fraction comprises hydrocracking at least a first portion of the second fraction and hydrocracking at least a portion of the fourth fraction.
 18. The method of claim 15, wherein the feedstock has a sulfur content of at least about 1.0 wt %, wherein the feedstock has a T95 boiling point of about 800° F. (˜427° C.) or less, wherein the feedstock has a T5 boiling point of about 350° F. (˜177° C.) to about 450° F. (˜232° C.), or a combination thereof.
 19. The method of claim 15, the method further comprising: separating the distillate boiling range product from the second fraction, the fourth fraction, or the combination thereof.
 20. A distillate boiling range fuel composition having a cetane index of at least about 50, an aromatics content of about 10 wt % or less, a naphthene content of at least about 50 wt %, a sulfur content of about 10 wppm or less, and an API gravity of at least about
 35. 21. A system for producing a fuel product fraction, comprising: a hydrotreating reactor comprising a hydrotreating feed inlet, a hydrotreating effluent outlet, and at least one fixed catalyst bed of a hydrotreating catalyst; a separation stage having a first separation stage inlet and a second separation stage inlet, the first separation stage inlet being in fluid communication with the hydrotreating effluent outlet, the separation stage further comprising a plurality of separation stage liquid effluent outlets, one or more of the separation stage liquid effluent outlets corresponding to product outlets; and a hydrocracking reactor comprising a hydrocracking feed inlet, a hydrocracking effluent outlet, and at least one fixed catalyst bed of a hydrocracking catalyst, the hydrocracking feed inlet being in fluid communication with at least one separation stage liquid effluent outlet, the hydrocracking effluent outlet being in fluid communication with the second separation stage inlet of the separation stage, and the hydrocracking catalyst comprising USY zeolite having a unit cell size of about 24.30 Å or less, a silica to alumina ratio of at least about 50, and an Alpha value of about 20 or less, the hydrocracking catalyst further comprising about 0.1 wt % to about 5.0 wt % of a Group 8-10 noble metal supported on the hydrocracking catalyst.
 22. The system of claim 21, wherein the separation stage comprises a divided wall column fractionator, the first separation stage inlet being different from the second separation stage inlet, the one or more product outlets being different from the at least one separation stage liquid effluent outlet in fluid communication with the hydrocracking feed inlet.
 23. The system of claim 21, wherein the separation stage comprises a common fractionator, the first separation stage inlet and the second separation stage inlet optionally comprising the same inlet.
 24. The system of claim 21, the system further comprising an additional hydrocracking reactor comprising an additional hydrocracking feed inlet, an additional hydrocracking effluent outlet, and at least one fixed catalyst bed of an additional hydrocracking catalyst, the additional hydrocracking reactor providing indirect fluid communication between the hydrotreating effluent outlet and the first separation stage inlet, the additional hydrocracking feed inlet being in fluid communication with the hydrotreating effluent outlet, the additional hydrocracking effluent outlet being in fluid communication with the first separation stage inlet. 